The hydrocarbons from oilfields most often comprise mixtures of crude oil and gas, with variable amounts of water, forming an aqueous phase in which sour gases, also present in the hydrocarbons, are dissolved at least partially, or even completely.
Under the effect of the differences in pressures and temperatures that occur on raising the hydrocarbons from the deep subterranean strata to the surface, the water present in said hydrocarbons can condense on the inside walls of pipelines, and mainly at the bottom of the pipelines (“Bottom of Line”, or “BoL”) and at the top of the pipelines (“Top of Line”, or “ToL”).
This acidic aqueous phase leads to considerable corrosion of pipelines, called “bottom-of-line corrosion” and “top-of-line corrosion” or “TLC”.
Top-of-line corrosion (TLC) is a phenomenon of global importance in the crude oil and gas extraction industry, and is particularly a source of problems both for offshore fields and for onshore fields (see for example the works of M. Singer et al. “Sour Top-of-the-Line Corrosion in the Presence of Acetic Acid”, Corrosion 67, (2011), 085003 sqq., or: http://corrosion.curtin.edu.au/research/topofline.cfm).
In fact, in conditions of laminar (or stratified) flow of the fluids being transported, and when coupled with conditions of condensation, internal corrosion is very often observed, localized at the top of horizontal pipelines. This corrosion is mainly due to condensation water at the top of the pipelines, which contains dissolved sour, gases, notably hydrogen sulphide (H2S) and carbon dioxide (CO2), but also organic acids, for example acetic acid.
More, precisely, in multiphase pipelines for conveying petroleum and/or wet gas in conditions of stratified, wave or wave-stratified flow, the liquid phase flows in the lower part of the pipeline, whereas the gas phase flows in the upper part of the pipeline.
The gas phase most often contains sour gases, such as CO2, H2S, but also acidic organic gases as well, such as acetic acid. As for the liquid phase, it contains hydrocarbons and an appreciable amount of water.
For protecting the inside wall of the pipeline against corrosion under the action of the acids, it is common practice for a corrosion inhibitor, which mixes with the liquid phase, to be injected in the pipeline, at the outlet from the extracting well. However, in conditions of stratified, wave or wave-stratified flow, only the lower part of the pipeline that is in contact with the liquid phase is effectively protected against corrosion.
Now, at present, higher and higher temperatures are being used for extraction of hydrocarbons, which greatly increases the risks of top-of-line corrosion. In fact, under the action of heat, the water contained in the liquid phase is transformed to steam, which condenses on the inside wall of the roof of the pipelines, which is cooled more or less abruptly by the cold external air and water (notably in the case of submarine pipelines).
This condensation water exerts a considerable corrosive action at the top of the pipelines, thus leading to considerable damage of said pipelines, ranging from simple pitting corrosion, to destruction of the wall and leakage of the hydrocarbons, which is totally unacceptable from the standpoint of protection of the environment. Such damage would lead to considerable economic losses, in terms of decontamination, losses of hydrocarbons, as well as in terms of repair of the damaged pipelines.
Numerous international conferences, gathering together world experts in matters of corrosion of pipelines for hydrocarbons, are regularly organized, and reflect the importance of the problem, notably because few chemical treatments are offered.
There are in fact already various chemical treatments, batch and/or continuous, which may or may not be combined with mechanical treatments, but they find little if any acceptance by industry, notably owing to their rather unsatisfactory effectiveness.
Among the various methods and devices proposed in the past, for preventing, or at least limiting, top-of-line corrosion of pipelines for hydrocarbons, one said method consists of sending into the pipeline one or more scrapers, of slightly smaller section than the internal section of the pipeline and spaced along the pipeline, the space between the scrapers being filled with a plug of inhibitor liquid. Patent application FR 2 791 695 proposes another scraper system, in combination with corrosion inhibitors.
Among the chemical treatments intended to limit corrosion of the carbonic type (due to CO2) and/or of the hydrogen sulphide type (due to H2S), the use of a great many inhibitors is recommended for effectively protecting the metal of the pipelines against one or other of these types of corrosion, by continuous or batch injection into the corrosive fluid, said fluid thus being distributed uniformly along said lines.
However, the treatment conditions prove tricky or even difficult, notably in the case when two or even three of the following parameters are combined: i) laminar (or stratified) flow of the corrosive fluid, cooling of the pipeline through lack of insulation and presence of organic acid (in particular acetic acid) in the liquid phase.
To combat this type of top-of-line corrosion (TLC), Y. M. Gunaltun et al. (“Control of top of line corrosion by chemical treatment”, NACE Corrosion, (2001), No. 01033) recommend batch treatment, or treatment by injection, with a long-lasting inhibitor comprising methyl diethanolamine (MDEA), in order to neutralize the acidity of the corrosive aqueous medium of the base matrix (BLC).
However, it was found that this amine does not neutralize the acidity of the condensate (droplets of condensed water) on the inside of the roof of said pipelines.
R. L. Martin, in “Inhibition of Vapor Phase Corrosion in gas pipelines”, NACE Corrosion, (1997), No. 337, and N. N. Andreev et al., in “Volatile Inhibitors for CO2 Corrosion”, NACE Corrosion, (1998), No. 241, proposed volatile corrosion inhibitors (VCI) at very high dosage (of the order of several percent).
G. Schmitt et al., in “Inhibition of the top of line corrosion under stratified flow”, NACE Corrosion, (2001), No. 01032, proposed the use of a so-called “creeping” inhibitor introduced into the corrosive medium like a conventional inhibitor. Owing to its very low surface tension, this type of inhibitor is said to creep along the wall to the top of the interior of the pipeline (twelve o'clock position), thus inhibiting top-of-line corrosion.
International application WO 2006/032774 describes inhibitors of top-of-line corrosion of pipelines for hydrocarbons, which are effective but can be further improved.
However, none of these known solutions provides, a suitable and really effective solution to the problem of top-of-line corrosion of pipelines for hydrocarbons used for extraction of hydrocarbons, such as petroleum and/or gas.
There is therefore a real need, reflected in constant pressure from industry, for new solutions and new treatments for effectively combating top-of-line corrosion of hydrocarbon pipelines.